Drilling fluids used in the drilling of subterranean oil and gas wells along with other drilling fluid applications and drilling procedures are known. In rotary drilling there are a variety of functions and characteristics that are expected of drilling fluids, also known as drilling muds, or simply “muds”. The functions of a drilling fluid include, but are not necessarily limited to, cooling and lubricating the bit, lubricating the drill pipe, carrying the cuttings and other materials from the hole to the surface, and exerting a hydrostatic pressure against the borehole wall to prevent the flow of fluids from the surrounding formation into the borehole.
Drilling fluids are typically classified according to their base fluid. In water-based muds, solid particles are suspended in water or brine. Oil can be emulsified in the water which is the continuous phase. Brine-based drilling fluids, of course, are a water-based mud (WBM) in which the aqueous component is brine. Oil-based muds (OBM) are the opposite or inverse. Solid particles may be suspended in oil, and water or brine is emulsified in the oil and therefore the oil is the continuous phase. Oil-based muds can be either all-oil based or water-in-oil macroemulsions, which are also called invert emulsions. In oil-based mud, the oil may consist of any oil that may include, but is not limited to, diesel, mineral oil, esters, or alpha-olefins. OBMs as defined herein also include synthetic-based fluids or muds (SBMs) which are synthetically produced rather than refined from naturally-occurring materials. SBMs often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbons alkyl benzenes, terpenes and other natural products and mixtures of these types. OBMs and SBMs are also sometimes collectively referred to as “non-aqueous fluids” (NAFs).
Damage to a reservoir is particularly harmful if it occurs while drilling through the pay zone or the zone believed to hold recoverable oil or gas. In order to avoid such damage, a different fluid—known as a “drill-in” fluid—may be pumped through the drill pipe while drilling through the pay zone.
Another type of fluid used in oil and gas wells is a completion fluid. A completion fluid is pumped down a well after drilling operations are completed and during the completion phase. Drilling mud typically is removed or displaced from the well using a completion fluid, which may be a clear brine. Then, the equipment required to produce fluids to the surface is installed in the well. A completion fluid must have sufficient density to maintain a differential pressure with the wellbore, which controls the well and to maintain the filter cake. The completion fluid must have sufficient viscosity and elasticity to maintain a suspension of bridging or weighting agents. The viscosity of a completion brine typically is maintained using polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosics. Unfortunately, although these polymers are water-soluble, they have a relatively low hydration rate in brines because very little water actually is available to hydrate the polymers in highly saline brines. Viscoelastic surfactants may also be used to viscosify drilling fluids, drill-in fluids, completion fluids, and the like.
It would be advantageous to improve the ability of drilling fluids, drill-in fluids, completion fluids and the like, to transfer heat from one portion of the wellbore, typically from the lower most or bottom portion, to cooler portions, namely the portions nearer the surface or to structures and environments on the surface. It would also be advantageous to improve the net specific capacity of drilling fluids, drill-in fluids, completion fluids and the like to absorb heat. As the quest for more and more oil and gas pushes explorers and operators to drill deeper, increasingly higher temperatures as wells become deeper increasingly become more of a factor in the functioning, durability and useful lifetime of equipment, tools, fluids and other structures used at these temperatures which may range as high as about 400° C. (about 752° F.). Indeed, conventional equipment at these temperatures may seize up or even melt and the only alternative may be to use expensive, exotic alloys. Similar problems may occur when equipment, such as pumps, are submerged. It would further be helpful to improve the methods and compositions for removing and redistributing the heat from these relatively hot portions of the wellbore and redistributing it to cooler portions of the wellbore or to structures and environments on the surface.